Offshore LNG regasification has become an acceptable alternative in LNG import and advantageously reduces safety and security concerns of LNG by delivering regasified LNG via a subsea pipeline to an existing onshore pipeline network. However, the so delivered regasified LNG may not always have the desired composition and heating value or Wobbe Index as LNG imports often vary significantly depending on the gas fields and the level of NGL (natural gas liquids) recovery at the LNG liquefaction plant.
Commonly, LNG conditioning to control the heating value (or Wobbe Index) is done onshore by dilution of the LNG with nitrogen. The amount of nitrogen dilution generally increases with the richness of the LNG. Unfortunately, the nitrogen dilution requirement also increases the inerts content of the regasified LNG and could reach 9 vol % when LNG with a heating value of 1170 Btu/scf is imported. This amount of nitrogen dilution would far exceed the typical pipeline gas specification of 3 vol % inerts. Therefore, even with nitrogen dilution for heating value control, the imported LNG must be restricted to the sources with heating values of less than 1,100 Btu/scf, which limits the LNG “spot market” strategy.
Prior Art FIG. 1 depicts a typical known offshore LNG regasification terminal and onshore facility that is equipped with gas heating and nitrogen dilution. The offshore facility receives LNG from LNG carrier 51 via LNG unloading arms 1 to the LNG storage tank 53. The offshore storage tank can be of various designs, either fixed or floating designs (e.g., LNG barge, LNG vessels, or gravity based structure). Vapors generated from the LNG ship during unloading and normal boil-off are recovered by compressing to the offshore fuel gas system. The LNG sendout, typically 200 MMscfd to 1,200 MMscfd, is pumped by in-take primary pump 52 to about 100 psig to feed the secondary pump 54. The high pressure pump discharge stream 2, typically 1,200 to 2,000 psig, is heated by the LNG vaporizers 81 to 40° F. forming stream 3 which enters the sub-sea pipeline 56. The regasification duty for 1,200 MMscfd of LNG sendout is about 660 MM Btu/hr for a typical LNG composition. Once the gas reaches onshore, the gas stream 4 is letdown in JT valve 90 to the pipeline network pressure, typically at 800 psig to 1,200 psig. The JT effect of the pressure letdown operation cools the inlet gas from 40° F. to about −20° F. forming stream 5. To meet the pipeline temperature specification, the pressure letdown gas is reheated using an onshore heater 91. The reheating requirement is about 120 MM Btu/hr for 1,200 MMscfd sendout. For heating value or Wobbe Index control of the sales gas, nitrogen dilution using stream 95 is injected to the reheated gas to meet pipeline specifications in sales gas 21.
Therefore, conventional offshore LNG regasification methods require significant heat input. Typically, regasification of 1,200 MMscfd of LNG sendout to 40° F. requires a total heating duty of about 780 MM Btu/hr supplied from seawater, fuel gas firing, or waste heat from power plants. Consequently, the use of energy-efficient, and environmentally friendly air exchangers is generally not practical for offshore installation due to the large real estate requirement. Unfortunately, most, if not all other types of known vaporizers have negative environmental impacts. For example, seawater vaporizers tend to destroy ocean life within its proximity, and the use of fuel firing creates gaseous emissions and liquid effluents. Further known methods of offshore LNG regasification facilities have been proposed as shown, for example, in U.S. Pat. No. 6,089,022 where LNG is regasified onboard an LNG tanker using seawater as the heat source before transferring the gas to an onshore facility.
Other known methods and configurations for Btu control of import LNG remove C2+ hydrocarbons from LNG in a process that includes vaporizing the LNG in a demethanizer using a reboiler, and re-condensing the demethanizer overhead to a liquid that is then pumped and vaporized (see e.g., U.S. Pat. No. 6,564,579). Offshore installation of such processes is very costly and problematic, particularly the hazard and safety risks associated with storing the so produced propane and heavier liquids.
Thus, while numerous configurations and methods of offshore LNG regasification are known in the art, numerous problems remain. For example, all known offshore regasification configurations generate emissions and/or have substantial environmental impact. Moreover, offshore Btu and heating value control is often impractical due to cost and safety concerns. Therefore, there is still a need to provide improved and environmentally acceptable methods and configurations for offshore LNG regasification that is efficiently coupled with onshore LNG processing for Btu and heating value control.